Field of the Invention
The invention relates to a plunger lift system to lift liquids out of a hydrocarbon well. In particular, the invention relates to a ball plunger lift system to lift liquids out of a highly deviated wellbore.
Background
Towards the end of the production life of a hydrocarbon well, formation liquids accumulate, at the bottom of the wellbore, to a level that significantly interferes with the well's performance. This necessitates employing measures to lift the formation liquid to the surface to prevent the accumulation of a sufficient volume of liquids that would kill the well. There are many different techniques for artificially lifting formation liquids including the plunger lift systems as those described in U.S. Pat. Nos. 6,209,637, 6,467,541 and 6,719,060, all herewith incorporated by reference in their entirety. Such plunger lift systems use a multipart piston (sleeve and ball, for example) that is dropped into a flowing well in separate pieces. When the pieces reach the bottom of the well, i.e. in the formation liquid, they unite to form the piston. A bumper spring at the bottom of the well cushions the impact of the ball and sleeve. Gas flowing into the well, below the piston, pushes the piston upwardly, thereby pushing any formation liquid towards the surface. The advantages of the multi-part piston is that such pistons may be dropped into the well without shutting in the well for a substantial time, thereby allowing the well to continue to produce gas while the piston falls to bottom. Known plunger lift systems also include single piece tubular-shaped pistons. Single piece pistons require the well to be shut in so the piston can fall to bottom.
There are problems, however, with using conventional tubular shaped plungers in high deviation wellbores, such as S-curve and substantially horizontal wellbores. S-curve wells are typically used, for example, in pad drilling where multiple wells are drilled in close proximity to each other at the surface (e.g., surface locations are 5-10 feet apart) but their bottom hole locations are located a substantial distance apart (e.g., 10-20 acres apart). Horizontal wellbore typically include relatively long horizontal portions that extend through the hydrocarbon bearing formation. In some wells, the horizontal portion extends in excess of 5000 feet. Friction prevents tubular shaped plungers from reaching bottom in highly deviated wells since the plunger tend to travel on the low side of the wellbore. Excessive friction also prematurely wears out the tubular shaped plungers as the plungers travel along the low side of the tubing. The friction wears out the external seals on the plunger thereby decreasing the effectiveness of the plunger's ability to lift liquids from the well bore thus requiring the frequent replacement of the plungers. This is both expensive and time consuming. The higher the deviation and the longer the deviated portion of a well, the quicker the conventional plungers wear out. Improved plunger lift systems particularly for highly deviated wellbores are, therefore, needed.